Abstract:In order to improve the wetting reversal and flushing effect of the flushing fluid for oil-based drilling fluid，the emulsion was formed by the cloud point effect of isomeric alcohol polyoxyethylene ether and octylphenol polyoxyethylene ether. At the same time，it was compounded with sodium diisooctyl sulfosuccinate（fast T）and span 60. By investigating the flushing efficiency and phase transition temperature of the flushing fluid，the formula of the flushing fluid was determined as follows，15% isomeric decanol polyoxyethylene ether（E1008）+ 6% octylphenol polyoxyethylene ether（OP-10）+ 3% fast T + 3% spandex 60. The temperature resistance，flushing efficiency，compatibility of the flushing fluid was investigated，the bond strength of cement after flushing with the flushing fluid was tested. The results showed that the flushing fluid had a temperature resistance of 170 ℃，and the flushing efficiency of 20% flushing fluid and spacer fluid was more than 95% within 7 min at 50—170 ℃. After flushing，the wellbore surface realized wetting reversal. The flushing fluid had good compatibility with drilling fluid and cement slurry. The flushing fluid had been applied in 10 wells and achieved good cementing quality.

Abstract:Conventional plugging materials are often difficult to balance the structural characteristics of deformability and high pressure，resulting in poor particle size matching and pressure sealing effect. Although existing shape memory plugging materials can deform at activation temperature and achieve adaptive sealing of cracks，they have problems such as low activation temperature and insufficient compressive strength，making it difficult to cope with harsh temperature and pressure environments in deep geological conditions. In response to these issues，a foaming resin material（SMFM）with high activation temperature and good shape memory performance was developed by using epoxy resin monomer（E51），curing agent triethylenetetramine（TETA）and polyetheramine（DP），and acrylic copolymer microspheres（PM）as raw materials. The pressure plugging performance and wall strengthening effect of SMFM were systematically evaluated. The results showed that when the mass ratio of E51，TETA，DP and PM was 0.05∶0.02∶0.02∶1.00，SMFM had good response performance，with a response rate of 92.9% . The glass transition temperature was 97 ℃，and then the recovery temperature was 130 ℃. Furthermore，the pressure bearing capacity could reach 10.3 MPa when the formula of plugging agent was made up of base paste and 5% SMFM，which had a good sealing effect on natural crack leakage. SMFM could adaptively match the crack width into the crack by changing its shape. After reaching activation temperature，it expanded from sheet materials or elliptical microspheres into block materials or circular microspheres，rapidly bridging in the crack，expanding under pressure，filling and sealing，and synergistically forming a sealing layer to reduce underground leakage and strengthen the wellbore. The plugging fluid formulated with high activation temperature shape memory foam material could be applied to high-temperature deep well crack leakage sealing.

Abstract:The conventional oil well cement stone is a hard and brittle material. Rubber particles have been extensively utilized to enhance the toughness of cement stone；however，the rubber is less compatible with the cement slurry and is easy to float，which restricts its effectiveness in the application. In this study，the micro-nanoparticle composite technology was used to prepare core-shell rubber composite particles by using rubber particles as cores and coating nano-silica on their surfaces. The effects of the obtained rubber composite particles on the properties of cement paste and the mechanical properties of cement stone were investigated. The results showed that four types of core-shell rubber composite particles were successfully prepared by micro-nano particle composite technology，and the most significant toughening effect was observed in styrene butadiene rubber （SBR） composite particles，and it had less effect on the flow properties of cement paste. It was found that the elastic modulus of cement gradually decreased with the increase of the coating amount of SBR composite particles，while the compressive strength showed an increasing trend，which indicated that the loss of compressive strength of cement due to the incorporation of rubber particles could be effectively compensated by increasing the coating amount of nano-silica. Further investigation revealed that when the coating amount of nano-silica was 5%，the optimal addition amount of SBR composite particles in cement slurry was 4%（BWOC），the elastic modulus of cement stone was 6.5 GPa. Compared with the cement stone without SBR composite particles，the elastic modulus decreased by 36.9% ，and the compressive strength was 30.8 MPa，increased by 38.1% ，indicating a significant toughening effect.

Abstract:To solve the problem of proppant backflow during frac-pack completion，the coated proppant with fast-curing feature at low temperature was prepared by surface grafting modification and characterized by means of scanning electron microscopy，energy spectrum analysis and infrared spectroscopy. The compatibility of proppant and sand-carrying fluid as well as the flow back control performance was studied by contrast test. The interaction between the molecules of the proppant coatings was investigated by first-principles calculation. The results showed that the coated proppant presented favourable compatibility with the sand-carrying fluid with the sand proportion of 5%—30%. The dimerization of the poly（vinyl pyridine）molecules was energetically favorable and spontaneous. The results of intermolecular interaction calculation showed that the coated proppant could enhance the stability of the proppant pack through the π-π interaction between polyethylene pyridine chain segments. Conductivity tests showed that the coated proppant possessed excellent fast-curing performance at low temperature. After being cured at the temperature of 50 ℃ for 2 hours， the conductivity of the proppant pack could be increased by 19.7%—53.1% and the critical backflow velocity of proppant could be increased by 1.6—3.0 times. It is of great significance to maintain the stability of the proppant pack under the conditions of low well temperature and rapid backflow at the end stage of fracturing sand control constructions.

Abstract:The existing self-heating system usually begins to generate heat during the ground preparation process，and then the heat and gas generated lost during transportation，making it difficult to efficiently act on the target layer. At the same time，for low-permeability reservoirs，the high surface tension of fracturing fluid leads to a low wave coupling coefficient in the target reservoir， which affects the multi-scale fracturing and crude oil driving capabilities of the fracturing fluid. Aiming at the performance defects of the thermal fracturing fluid mentioned above，a novel sustained self-heating energy-enhancing oil displacement fracturing fluid system was developed. Based on the exothermic reaction of carbamide and sodium nitrite in hydrochloric acid solution，the self-heating system was prepared by adding hydrochloric acid solution with free or water in oil emulsion liquid respectively. A small molecule polymer enhanced oil displacement agent was prepared using maleic anhydride，2-acrylamido-2-methylpropanesulfonic acid，dimethyl succinate， glycidyl methacrylate，acrylamide，and sodium ethylbenzenesulfonate as monomers. This article studied the sustained heat generation and gas production capacity of the heat generating system，the surface/interface activity and the viscosity reduction ability of the enhanced oil displacement agent，and the compatibility and oil displacement effect of the two. The results showed that the heat generating system could release heat and produce gas twice during the injection process and after 40 minutes of injection，with a temperature of over 80 ℃. It could simultaneously achieve the effects of hot fluid injection and reservoir heating，leading crude oil viscosity reduction and reservoir energy enhancement. When the dosage of enhanced oil displacement agent was 1500 mg/L，the surface tension of fracturing fluid could be reduced to 25 mN/m，the interfacial tension between fracturing fluid and crude oil could be reduced to 0.0008 mN/m，and then the viscosity of crude oil at room temperature could be reduced from 152.8 mPa·s to 38.2 mPa·s. The compatibility between heat generating system and oil displacement agent was good. The mixture remained stable even after 12 hours of static mixing. The recovery rate of compound use was significantly higher than that of water flooding by 19.5 percent points.

Abstract:In view of the water blocking damage problem faced in the process of oil exploitation and the current situation that traditional fluorine-based waterproof lock agents are expensive and cause water pollution，in the paper，the emulsified silicone oil was used to replace fluoride and a non-fluorine waterproof lock agent J-C-0 was prepared with surfactant octadecyl trimethyl ammonium chloride as the emulsifier. The surface tension，interfacial tension，wettability，contact angle and self-imbibition of the agent were tested and compared with that of fluorine-based water blocking agents，namely perfluorononenoxy benzene sulfonate （OBS），and fluorinated acrylate copolymer（PFAc）. The research results showed that when the mass ratio of dimethyl silicone oil to octadecyl trimethyl amine was 8∶1 and the dosage was 0.3%，the surface tension of the waterproof lock agent J-C-0 system could be reduced to 26 mN/m. The waterproof lock agent J-C-0 system could increase the contact angle of the core from 23.71° to 88.93°， changing the wettability of the core from strong hydrophilicity to weak hydrophilicity. Compared with the waterproof lock agents OBS and PFAc，J-C-0 had better temperature and salt resistance. The waterproof lock agent J-C-0 had lower spontaneous imbibition water amount and higher permeability recovery rate. The permeability recovery rate of the core treated with 2% NaCl + 0.3% J-C-0 was 83.51% . As a non-fluorine waterproof lock agent，J-C-0 performes excellently in reducing water lock damage，has a good application prospect，and is expected to solve many problems of traditional fluorine-based water blocking agents.

Abstract:The use of gel plugging is an important technology for achieving balanced displacement and enhancing oil recovery in high water cut reservoirs. Under the conditions of high temperature and high salinity reservoir，the stability of the gel deteriorates， and it is easily broken through by subsequent injection fluids under production pressure differences，resulting in a low gel plugging rate. Therefore，it is necessary to propose effective ways to improve the performance of the gel. In the article，micrometer sized fly ash was added into the gel system，by the measurement of the rheological property of the gel system，the injection performance， gelation time，high-temperature stability，and fracture stress of phenolic gel system filled with fly ash was investigated. The results showed that when the amount of fly ash was 1%—2%，the viscosity of the gel forming solution was 20.6—33.4 mPa s，exhibiting good pumping performance. The gelation process was slightly delayed，with a 2—4 hour extension of gelation time at 90 ℃ and 150 ℃. The high-temperature stability of the gel system was significantly improved，and the stability time at 150 ℃ was extended from 20 days to more than 120 days. The storage modulus of the gel increased from 7.4 Pa to 25.2—49.8 Pa，while the fracture stress remained almost unchanged with the amount of fly ash used. The addition of fly ash could effectively improve the thermal stability and plugging strength of the gel. In field experiments，fly ash enhanced gel has shown good water control and oil incremental effect.

Abstract:In order to solve the problems of high injection pressure and difficult injection in the injection process of conventional polymer gel，the hydrogel system with low initial viscosity and easy degradation was prepared，and the injection and gelation properties of the gel system were investigated. The microstructure and mechanical strength of the composites were studied by scanning electron microscopy（SEM）and universal mechanical testing machine. Furthermore，the heat resistance and thermal stability of the gel were evaluated by thermogravimetric analysis and gel dehydration rate test. Finally，the degradability and plugging performance of the gel were evaluated by degradability experiments and physical simulation experiments. The results showed that the formulation of seawater-based hydrogel system suitable for unconsolidated sandstone reservoirs with low initial viscosity and easy degradation was as follows，0.2 % polymer VC-1+2% itaconic acid+0.7% melamine+0.1% sodium thiosulfate， and the gelation temperature range of the gel system was 50— 90 ℃，the gelation time was regulated within 5—22 h，and the compressive strength（90 ℃）was 310.4 kPa，exhibiting high mechanical strength. The dehydration rate of the gel at 90 ℃ for 90 d was only 7.4%，and the maximum temperature resistance reached 201.1 ℃，showing good long-term stability and thermal stability. The gel had good plugging and degradability. In the physical simulation experiment，the breakthrough pressure of the gel reached 3.99 MPa，and after the first water flooding breakthrough，the secondary migration plugging could be carried out. When the mass ratio of the degradation solution QC-1 to the gel was 1∶2，the degradation rate of the gel reached 98.2% after aging for 10 days at the temperature of 70 ℃. When the water plugging operation was carried out by using the developed hydrogel system，the average daily oil production of typical wells increased from 2.3 t to 62 t，the water cut decreased from 99.7% to 72.4%，and the crude oil production increased by stages reached 2710 t，which could significantly increase oil well production and reduce water cut.

Abstract:Plugging agent plays a key role in the process of oil development，quality improvement and efficiency enhancement. However，there are some problems such as insufficient plugging strength，short validity period and low water plugging efficiency， which considerably affect the practical application. Therefore，the research on high-strength plugging system becomes a hot topic in oil production. In this paper，a kind of organic cross-linked gel plugging agent was developed，with polyhydroxyethylacrylamide （PHEAA）as the skeleton molecule，1，6-hexane diisocyanate（HDI）as the crosslinking agent，and a mixed solution containing N，N-dimethylformamide（DMF）and dimethyl sulfoxide（DMSO）as the solvent. The organic plugging system could undergo sol-gel phase transition under constant temperature conditions. The effects of the dosage of PHEAA and HDI and temperature on the properties such as gelation time and gel strength were investigated. Furthermore，the effect of plugging system on water plugging and profile control of sand-filled pipe was evaluated. The results showed that the strength of the gelled organic gel was proportional to the concentration of PHEAA and HDI，while the gelation time was adversely proportional to the temperature. When the dosage of PHEAA and HDI increased from 10%，2% to 16%，7%，the corresponding storage modulus increased from 991 Pa to 3100 Pa， and then the viscosity increased from 22 400 mPa s to 45 100 mPa s，respectively. In addition，accompanying with the increase of component content，the gelation time of plugging agent system obviously shortened，which reduced from 1 h to 20 min. When the temperature increased from 45 ℃ to 125 ℃，the gelation time decreased from 3 h to 13 min. The SEM scanning results showed that the state of plugging system changed from liquid film to irregular three-dimensional crosslinking network after gelation. The solid-state transition of the system was mainly attributed to the nucleophilic reaction between HDI and hydroxyl groups in PHEAA. In the sand-packing pipe plugging experiment，after injecting 1 PV liquid plugging system and heating for 6 h at 85 ℃，the plugging strength after solidifing could reach up to 26.11 MPa，showing good effect of water plugging and profile control.

Abstract:When conventional plugging agent is used for deep profile control and flooding in medium-low permeability reservoirs，there is a contradiction between injection and plugging ability，so the effect of profile control and flooding is poor. The retarded authigenic gas foam gel（RAGFG）system was developed by adding gas generating agent ammonium chloride and sodium nitrite， retarder，crosslinking agent chromium acetate and surfactant alkyl amide propyl betaine FM into polymer solution. The gas production performance，rheological properties，injectivity and plugging performance of the system were investigated，and the mechanism of the deep profile control and flooding of the system was discussed. The results showed that the gas production time of the RAGFG system could reach more than 155 h，and the gas production efficiency was 77.38%. Compared with the gel system， the obtained foam gel had higher apparent viscosity，yield stress and viscoelasticity. The injection pressure of the RAGFG system in the sand filling pipe with the permeability of 158×10^-3 μm² was only 0.12 MPa，the breakthrough pressure could reach up to 7.58 MPa，and the plugging rate was 99.0%. The double-tube parallel experiment with a permeability difference of 10 showed that the gas-liquid ratio of the RAGFG system was continuously increased during the migration process，and the viscoelasticity was gradually enhanced. Therefore，the RAGFG system had the characteristics of enhancing the plugging ability along the way. The diversion rates of sand-filled pipes with permeability of 1025×10^-3 and 92×10^-3 μm² could be changed from 95 % and 5% to 60% and 40%，respectively，and the plugging ability of the system to high permeability pipes declined little after 7 PV of subsequent water flooding. The visual oil displacement experiment confirmed that the RAGFG system could enhance oil recovery by 29.73 percentage points. Therefore，the RAGFG system had the characteristics of“slow gas production and foaming + delayed gel crosslinking + step-by-step enhanced plugging”，which is expected to be applied to medium-low permeability and high water cut reservoirs to enhance oil recovery.

Abstract:The oil reservoirs in the western South China Sea have entered a high water cut stage with significant reservoir heterogeneity. High-temperature profile control is urgently needed for injection wells to improve oil recovery. Aiming at the high temperature（130 ℃），high salt（32 385 mg/L salinity，5650 mg/L calcium and magnesium ion content）environment of the oil reservoir in the western South China Sea and the failure of conventional organic gel channeling sealing system，a nano-silica toughened gel with temperature resistance and salt resistance was prepared by using acrylamide and 2-acrylamide-2-methylpropane sulfonate sodium copolymer（GW-1），resorcinol，urotropine，acetic acid and amine modified nano-silica toughened agent（20 nm） as raw materials，and then the gel formula was optimized. The gelation kinetics equation of gel at 90—130 ℃ was obtained by the relationship curve between gelation time and crosslinking agent dosage. Finally，the viscoelasticity，injectivity and plugging ability of nano-silica toughened gel were evaluated and compared with those of none-toughened phenolic gel. The results showed that the optimum formula of nano-silica toughened phenolic gel was obtained as follows：0.8% GW-1，0.2% resorcinol，0.4% urotropine， 0.2% acetic acid，0.3% thiourea and 0.02% modified nano-silica. The gelation time was 8 h，the strength grade of gel was G，and then the dehydration rate was less than 10% after aging 95 days at 130 ℃. The gelation time of gel was mainly affected by temperature. The higher the temperature，the shorter the gelation time was. The gelation activation energy of phenolic gel at 130 ℃by calculation was 88.2 kJ/mol. Compared with the non-toughened phenolic gel，the nano-silica toughened phenolic gel could increase the residual resistance coefficient of sand filling pipe from 88.3 to 963.0，the plugging rate from 98.9% to 99.9%，and the breakthrough pressure gradient of subsequent water drive from 3.45 MPa/m to 34.7 MPa/m. The amine modified nano-silica toughened gel gave the gel a suitable network structure，provided a support skeleton for the gel，and then enhanced its temperature and salt resistance，viscoelasticity and aging stability. The nano-silica toughened gel had good injectivity，long-term stability and plugging performance，which was suitable as a channeling sealing agent for offshore high-temperature and high-salinity reservoirs.

Abstract:In response to the limitation of chemical flooding systems based on surfactants and polymers in enhancing oil recovery in high-temperature（＞100 ℃）and high-salinity（＞22.5×10⁴ mg/L）channel sand reservoirs，it was proposed to modify nanomaterials to simultaneously improve water flooding sweeping efficiency and microscopic oil washing efficiency. Firstly，the chemical modification of nano-SiO₂ was carried out，then the ability of modified nano-SiO₂ to form viscosity increasing emulsion with crude oil，the ability to reduce interfacial tension and the feasibility of enhancing oil recovery under heterogeneous conditions were studied. The experimental results showed that the modified nano-SiO₂ had a surface branching number of 10⁵. The modified nano-SiO₂ could form viscosity increasing W/O emulsion with crude oil in the water cut range of 10%—80%，and the viscosity of emulsion was 2—10 times of the viscosity of crude oil. Modified nano-SiO₂ could reduce the interfacial tension between oil and water to 10^-3 mN/m. Modified nano-SiO₂ in porous media improved macroscopic sweep efficiency through flow control and Jamin effect，and enhanced microscopic oil washing efficiency by reducing interfacial tension. After water flooding to a water cut of 98%， modified nano-SiO₂ flooding and subsequent water flooding could enhance oil recovery by more than 25% percentage point. All experimental results indicated that the tackifying active nano-SiO₂ was feasible for improving oil recovery in channel sand reservoirs.

Abstract:With the development of fractured bottom water reservoirs，the phenomenon of bottom water channeling is becoming more and more serious，resulting in high water cut and inefficient production of oil wells. Strong heterogeneity is the main reason for water channeling in fractured bottom water reservoirs，and the core of water channeling control is to clarify the law of bottom water channeling and explore the efficient water plugging and profile control process of bottom water reservoirs. Based on the geological characteristics of Caogu 1 buried hill reservoir，the influencing factors of water channeling in the bottom water reservoir was analyzed and the optimal injection slug plug parameters of the water plugging system was optimized，which provided a theoretical basis for the water channeling control of fractured bottom water reservoirs. Firstly，with the help of the self-developed three-dimensional visual physical model of fractured bottom water reservoirs，the specific influence mechanism of bottom water energy，well control fracture location and heterogeneity on water channeling in fractured bottom water reservoirs was explored. Secondly，the slug parameter optimization experiment was carried out by selecting the temperature-resistant gel and nano-graphite reinforced foam system suitable for Caogu 1 buried hill reservoir. The experimental results showed that the bottom water energy increased from 1 mL/min to 5 mL/min，the inclination angle of the bottom water cone was reduced by 24°，the water breakthrough time was advanced from 0.20 PV to 0.11 PV，and the recovery rate was reduced by 8.5%. The inclination angle of the water cone at the heel end of the straight inclined well increased by 20° compared with that at the toe end，the water discovery time was delayed by 0.06 PV，and the recovery rate increased by 7%. In the low permeability zone，the heel end of the straight inclined well moved to the toe end，the inclination angle of the water cone increased by 25°，the water breakthrough time lagged by 0.09 PV，and the recovery rate increased by 6.1% . it was determined that the optimal slug injection combination was as follows：nano-graphite reinforced foam was injected first and then temperature-resistant gel，the optimal injection amount of slug was 0.3 PV oil layer，and the optimal slug injection rate was 3 mL/min，compared with the injection of single foam or gel，the inclination angle of the water cone increased by 37—39°，the water breakthrough time was delayed by 0.09—0.17 PV，and the subsequent recovery degree of bottom water flooding increased by 5.0 percentage point—12.3 percentage point. It provides a solution for water channeling control in fractured bottom water reservoirs.

Abstract:Carbonized intelligent water flooding is a new chemical combined oil recovery method. How to improve the solubility of CO₂ in salt water is the key to effectively reduce the interfacial tension between oil and water. The formation water with high salinity was diluted as smart water，and CO₂ was added to the smart water with different concentrations of mutual solvent under different pressures. The interfacial tension measurement experiment was carried out to study the influence of mutual solvent on the interfacial tension between smart water（or carbonized smart water）and crude oil，and the influence of salinity，mutual solvent concentration and pressure on the interfacial tension of oil and water was clarified. The experimental results showed that the density of the mixed liquid and carbonized smart water decreased with the increase of the concentration of organic mutual solvent，and with the increase of the system pressure，the density of the mixed liquid slightly increased，while the density of the carbonized smart water decreased. Under constant pressure，the interfacial tension between the mixed liquid and crude oil decreased with the increase of the mutual solvent concentration in the mixed liquid，and decreased with the decrease of the salinity，but it was less affected by the system pressure. The decrease of the interfacial tension of the mixed liquid under the action of DME was greater than that under the action of methanol. When CO₂ was added to smart water，the interfacial tension of oil and water could be further reduced. The interfacial tension between carbonized smart water and crude oil decreased with the increase of mutual solvent concentration，and decreased with the decrease of salinity and system pressure. The interfacial tension between the carbonized smart water and crude oil was the smallest when 10% formation water was added with 15% DME and then 9 MPa CO₂ was added，and the interfacial tension was reduced by 88.2%. The research results provide a new method for the continuous development of old oil fields with high water cut and the improvement of water flooding recovery.

Abstract:Tight reservoirs are typically developed through large-scale hydraulic fracturing to effectively connect natural fractures， which significantly influence CO₂ huff-n-puff oil recovery. To clarify the characteristics of oil mobilization under different fracture conditions in tight reservoirs，CO₂ huff-n-puff nuclear magnetic resonance（NMR）experiments were conducted for varying fracture apertures，as well as microscopic visualization experiments under multi-scale fracture conditions. The effects of fracture aperture and fracture density on CO₂ huff-n-puff performance were systematically investigated. The results showed that under single fracture conditions，an increase in fracture aperture significantly enhanced the oil recovery degree of both fractures and surrounding matrix. When the fracture aperture increased from 20 μm to 70 μm，the cumulative oil recovery degree after four cycles of CO₂ huff and puff improved by 9.20 percentage points. Under multi-scale fracture conditions，an increase in fracture density enhanced reservoir connectivity and expanded the sweep area of CO₂. Compared to simple fracture model，the matrix oil recovery degree in complex fracture model increased by 4.26 percentage points after four cycles of CO₂ huff and puff. The enhancement in recovery factor of multi-scale fracture primarily occurred during the first two huff-n-puff cycles，with the incremental oil recovery effect diminishing in subsequent cycles. Increasing fracture aperture and fracture density could effectively improve matrix oil mobilization in tight oil reservoirs. The research results could provide theoretical guidance and technical support for enhancing oil recovery of CO₂ huff and puff in tight oil reservoirs.

Abstract:In the Ba-21 Block of Xinjiang oilfield，residual oil is predominantly concentrated in low-permeability zones，making CO₂ flooding a promising enhanced oil recovery（EOR）technique. However，significant reservoir heterogeneity，combined with the mobility contrast between CO₂ and crude oil，increases the risk of gas channeling. Water-alternating-gas（WAG）injection，a widely used method to mitigate gas channeling，requires further evaluation to determine its effectiveness in this setting. This study investigated the influence of WAG injection on the performance and oil recovery of CO₂ flooding under heterogeneous conditions， using natural conglomerate cores with varying permeabilities representative of Ba-21 Block. The results showed that CO₂ readily interacted with Ba-21 crude oil，enabling efficient displacement. However，elevated injection rates and permeability levels accelerated oil production while intensifying CO₂ channeling，leading to rapid declines in oil output. For the main reservoir intervals （liquid permeability ranging from 3.1 × 10-3 μm2 to 25.5 × 10-3 μm2），WAG injection with a 1∶1 slug volume ratio effectively suppressed intra-layer channeling，enhancing oil recovery by 34.1 percentage points—50.6 percentage points compared to continuous CO₂ flooding. However，as permeability increased，the flow resistance established by WAG weakened，and the presence of water reduced the extraction efficiency of CO₂ . As a result，C7—C14 alkane content in produced oil decreased. When both interlayer and intralayer heterogeneities were present，the effectiveness of WAG in controlling gas channeling was further compromised. In conglomerate cores with a gas permeability contrast of 4.1，WAG improved recovery by less than 7 percentage points. In contrast，foam flooding，offering superior mobility control，significantly enhanced following WAG injection，increasing oil recovery by 26.8 percentage points and 12.2 percentage points in high- and low-permeability cores，respectively. These findings provided theoretical and technical support for assessing WAG feasibility in Ba-21 Block and offered valuable guidance for optimizing gas channeling control strategies in similarly heterogeneous reservoirs during CO₂ flooding.

Abstract:under the“Carbon Peaking and Carbon Neutrality”target，traditional steam injection thermal recovery methods such as steam huff -puff and steam flooding exist in a series of problems such as high cost，high energy consumption and high carbon emissions. It is urgent to find new technologies to improve the development effect. Catalytic aquathermolysis of heavy oil is an effective technology for its recovery and has achieved significant developments in recent years. In the article，the Q40 block heavy oil in Liaohe oilfield was taken as the research object，the indoor high-temperature catalytic aquathermolysis reaction of heavy oil was conducted at different temperatures，time and concentrations of nano-copper based catalyst systems using high-temperature and high-pressure reactors indoors. By measuring the viscosity，group composition，and gas composition of the crude oil before and after the reaction，the viscosity reduction and upgrading effect and mechanism were systematically studied. The experimental results showed that the reducing viscosity and upgrading effect could not be achieved relying solely on high-temperature treatment. The addition of nano-copper based catalyst system had the reducing viscosity and upgrading effect on crude oil. As the concentration and reaction time of the reagent system increased，the viscosity of crude oil decreased after the high-temperature reaction，the content of saturated hydrocarbons and aromatics in the light components of crude oil significantly increased，and the content of asphaltene and gum in the heavy components significantly decreased. When the catalyst concentration increased from 0.3% to 0.75%，the viscosity of the crude oil after the reaction decreased from 1899 mPa·s to 1164 mPa·s，and the viscosity reduction rate increased by 7.3%. The viscosity of crude oil samples subjected to high-temperature reaction for 3 days decreased by 49.5% compared to those subjected to high-temperature reaction for 0.5 days. The reaction temperature had a relatively small impact on the effectiveness of the catalytic system. After high-temperature catalytic aquathermolysis reaction at 180 ℃，the viscosity of crude oil decreased from 10 940 mPa·s of the base oil sample to 1765 mPa·s，with a viscosity reduction rate of 83.9%. The viscosity of crude oil after reaction at different temperatures（180—260 ℃）had little difference，especially when the reaction temperature exceeded 200 ℃， the viscosity reduction rate of crude oil changed little. The nano-copper based catalyst system has strong temperature adaptability， wide effective temperature range，good reducing viscosity and upgrading effect on heavy oil.

Abstract:Polymer flooding is a mature and important technology to enhance oil recovery. Due to the injection process and high-speed shear in the process of polymer preparation and injection，the viscosity loss of polymer is serious，the mobility ratio is reduced，the spread capacity is reduced，and the oil recovery is affected. In order to solve the problem of polymer shear resistance， the dissolution，shear，seepage and oil displacement properties of microencapsulated emulsion polymer with polyurethane as shell material were studied. The study showed that the microencapsulated polymer presented the morphology of capsule microspheres， and the average particle size of the microspheres was about 500 nm. The microencapsulated polymer began to show signs of shell breaking at 3 h，during the continuous stirring process in water，the shell was quickly broken after 6 h，and the full shell breaking time was about 13 h. In the process of seepage in porous media，when the microencapsulated polymer migrated to 1.33 m（10.6 h）， the shell began to be broken；the shell rapidly was broken after migrated to 2 m（16 h），and the shell was fully broken after migrated 3.33 m（26.6 h），the shell was fully broken and the polymer was released. The molecular chains of the polymer aggregated with each other in the aqueous solution，showing a relatively dense network structure and obvious viscosity increasing characteristics. In homogeneous and heterogeneous cores，the oil recovery of microencapsulated emulsion polymer was higher than that of HPAM by more than 6 percentage points. The viscosity loss rate of the microencapsulated emulsion polymer after high-speed mechanical shear was only 5%，so high resistance coefficient and residual resistance coefficient could be established in the porous medium，which could realize the expansion sweep and enhancement of oil recovery.

Abstract:The Fang 2 block in the peripheral Songfangtun oilfield has entered a high water-cut development stage，presenting challenges including ineffective water flooding control，a high proportion of low-production wells，and numerous long-term shut-in wells. The conventional inverted nine-spot well pattern configuration can no longer meet the requirements of current efficient exploitation. To address these issues and enhance block recovery efficiency，a“secondary-tertiary combination”development model was adopted，incorporating middle-phase microemulsion flooding technology along with laboratory experiments and reservoir numerical simulation to propose a new development plan. The results showed that when using the compound surfactant system of sodium dodecylbenzene sulfonate and coco-fatty acid ester polyoxyethylene betaine（mass ratio 1∶3）as the core surfactant for middle-phase microemulsion，the system achieved optimal performance with 0.5% dosage of compound surfactant. The optimum mass fraction of n-butanol as cosurfactant was 9.4% determined by alcohol scanning method，and then the optimized salinity value was 4.3% NaCl. In the sand-packed model oil displacement experiment，the injection of middle-phase microemulsion increased the recovery rate by 24.65 percentage points. Furthermore，the existing well pattern was optimized to a five-spot configuration，and then the well spacing adjusted to 195.1 m. After combining secondary water flooding well pattern intensification with tertiary recovery and through CMG numerical simulation prediction，the middle-phase microemulsion injection at 86% water cut could enhance recovery by 20.42 percentage points. The cumulative incremental oil production projected to reach 319 300 t. The research results not only provided effective technical solutions for the development of Fang 2 block in Songfangtun’s peripheral oilfield，but also offered theoretical foundations and practical references for developing other continental low-permeability reservoirs.

Abstract:Asphalt deposition is a key challenge faced in crude oil extraction and transportation，which not only leads to a decrease in oil well production，but also causes the pore channels blockage during oil extraction and pipeline blockage during transportation in severe cases. The most common strategy to prevent or reduce asphaltene deposition is to use asphaltene dispersants to increase asphaltene stability and reduce asphaltene aggregation. The purpose of this paper was to elucidate the effect and mechanism of asphaltene dispersant on asphaltene stability. 4-Nonylphenol（NP）was selected as the asphaltene dispersant，and the effect of dispersant on asphaltene stability was investigated by the mass-fraction conductivity method. The mechanism of the dispersant was investigated from the perspective of tertiary structures，such as the molecular structure，the structure of aggregates and the structure of clusters，respectively，by means of FT-IR，XPS，XRD，TEM，particle size distribution，and zeta potential analysis，etc. The results showed that the addition of dispersant significantly improved the stability of asphaltene，which was adsorbed on the surface of asphaltene molecules through intermolecular hydrogen bonding and other interactions，and increased the spatial resistance between asphaltene molecules，increasing the asphaltene lamellar spacing from 0.34 nm to 0.36 nm，which also reduced the asphaltene binding，resulting in the disassembly and depolymerisation of asphaltene binders and their cluster structures based on the original behaviour. The number of layers of asphaltene aggregates decreased from 7.15 to 5.49，the particle size of the asphaltene clusters rapidly decreased by more than 70% and the zeta potential increased significantly. Finally，the asphaltene clusters were prevented from further growth into flocs，thus reducing and preventing asphaltene deposition.

Abstract:In the field operation，when testing the solid phase content of drilling fluid，it was found that the measured value of solid phase content of drilling fluid with formate was seriously deviated from the real situation. According to the volume fraction of solid phase，the measured result was generally higher than the actual value by 3%—8%. Furthermore，the higher the formate content， the higher the deviation degree was. The commonly used salt content correction means were no longer applicable to the drilling fluid system containing formate. Based on the K⁺ content value，the author established the relationship between K⁺ content and HCOOK content，HCOOK content and the measured value of drilling fluid solid phase，HCOOK content and the change of liquid phase density of the system，and the relevant quantities of solid phase composition analysis through data fitting，so that the solid phase content correction calculation could be carried out for drilling fluid with HCOOK added. Considering that both KCl and HCOOK were often used in field operations to increase K + required by drilling fluid system，the type of salt that provides K + could be determined by the principle of ion balance based on the Cl- content measurement and analysis data in drilling fluid operations and the background value of formation salt content. In actual construction，K⁺ was always in the dynamic change of“consumption-supplement”. In order to better analyze and judge the change of K⁺ quantity combined with actual construction information，the calculation method of K⁺ consumption was given in this paper，which could be used as a reference for on-site drilling fluid maintenance and treatment. The processing results of the measured solid content data showed that the data analysis and processing method provided in this paper could effectively eliminate the error in determination of the solid content of drilling fluid containing formate.

Abstract:As oil and gas exploration and development continue to advance，the geological conditions encountered in drilling engineering are increasingly complex. Loss circulation issues have become one of the key factors restricting drilling efficiency and safety. Loss circulation materials（LCMs）have long been recognized and developed as an essential means to address these issues. In this paper，the recent progress in the application and research of LCMs in drilling engineering was reviewed，with a focus on analyzing the plugging mechanisms，performance characteristics and applicable conditions of various types of LCMs，including bridging lost circulation material，fast fluid loss plugging material，polymer gel plugging material，curable plugging material， smart plugging material. Finally，the prospect of LCMs in drilling engineering was put forward.

Abstract:Temporary plugging and well-killing technology are widely used in well repair operations in oil and gas fields to solve the problems of well-killing fluid leakage，gas invasion，and high-pressure well failure during well repair. In this paper，the research progress of temporary plugging technology in well repair operations in my country was summarized，the research progress and application of different types of temporary plugging agents was focused on，and the advantages and limitations of various types of temporary plugging agents under different formation conditions was pointed out. Through the analysis of relevant literature，the application trends and future research directions of different types of temporary plugging agents were demonstrated，providing a reference for further research on temporary plugging and well-killing technology.

Abstract:With the proposal of the "double carbon" goal and the development of carbon capture，utilization and storage（CCUS）， CO₂-reactive surfactants have been paid more and more attention. In this paper，the recent advances of CO₂-reactive surfactants were reviewed from the aspects of structural characteristics，physicochemical properties，as well as their applications in oilfield development. CO₂-reactive surfactants usually contain nitrogen-containing groups，carboxylic acid，phenol and other groups that can react with H⁺ generated by CO₂ dissolving in water. The types and properties of surfactants will change after the reaction，and the surface activity will change to a certain extent. After the reaction，the viscosity of the system，emulsification effect on crude oil and foaming characteristics will be greatly changed. Meanwhile，the transformation of these properties can be regulated by the introduction and elimination of CO₂ . It is proved that the CO₂/ surfactant solution injection can control CO₂ gas channeling to a certain extent and improve oil displacement efficiency in the development of the oil field. If the regulative properties of CO₂-reactive surfactants can be successfully used in the oil field development，and the synergistic effect of CO₂ and surfactants can be fully utilized，the oil production recovery will be greatly increased.

Abstract:Inorganic mineral scaling is one of the most common oilfield chemical problems in the process of oil and gas development，which greatly affects the efficiency of oil and gas development，production and transportation. In recent years，shale oil and gas play an increasingly important role in China 's energy landscape. However，the extremely low porosity of shale oil and gas reservoirs leads to scaling of inorganic minerals，which brings more serious problems. Because China is mainly dominated by continental shale oil，the key factors such as reservoir formation mechanism，thermal evolution degree，diagenesis strength and mineral composition are very different from those of marine shale oil in North America，which leads to different fracturing technologies and fracturing fluid formulations. The formation mechanism of scaling is very different from that of North America， which also poses a great challenge to scaling prevention and control. In order to support the scale prevention practices in shale oil production of China，based on the characteristics of shale reservoirs in China，the differences and typical characteristics of scaling mechanisms caused by different development technologies resulting from different shale reservoir endowments was summarized. Furthermore，the research advances were systematically summarized from the aspects of scaling causes，scaling risk predictions and scale inhibition mechanism and kinetics. Finally，aligned with the current research status and actual engineering needs in China，the urgent problems to be solved in the future research on scaling in theoretical basic research，industry norms and standards development and engineering application were put forward，which provided reference and guidance for further research on scaling mechanism and development of prevention and control technology from the perspective of oilfield chemistry.